Wellbores utilizing fiber optic-based sensors and operating devices

ABSTRACT

This invention provides a method for controlling production operations using fiber optic devices. An optical fiber carrying fiber-optic sensors is deployed downhole to provide information about downhole conditions. Parameters related to the chemicals being used for surface treatments are measured in real time and on-line, and these measured parameters are used to control the dosage of chemicals into the surface treatment system. The information is also used to control downhole devices that may be a packer, choke, sliding sleeve, perforating device, flow control valve, completion device, an anchor or any other device. Provision is also made for control of secondary recovery operations online using the downhole sensors to monitor the reservoir conditions. The present invention also provides a method of generating motive power in a wellbore utilizing optical energy. This can be done directly or indirectly, e.g., by first producing electrical energy that is then converted to another form of energy.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Divisional of U.S. patent application Ser. No.09/071,764 filed on May 1, 1998, now U.S. Pat. No. 6,281,489 (the“Parent Application”). The Parent Application claims priority fromProvisional U.S. patent application Ser. No. 60/045,354 filed on May 2,1997; 60/048,989 filed on Jun. 9, 1997; 60/062,953 filed on Oct. 10,1997; 60/073,425 filed on Feb. 2, 1998; and 60/079,446 filed on Mar. 26,1998. Reference is also made to a U.S. patent application Ser. No.09/070,953 filed on May 1, 1998, now U.S. Pat. No. 6,268,911 thecontents of which are incorporated here by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates generally to oilfield operations and moreparticularly to the downhole apparatus utilizing fiber optic sensors anduse of same in monitoring the condition of downhole equipment,monitoring certain geological conditions, reservoir monitoring andremedial operations.

2. Background of the Art

A variety of techniques have been utilized for monitoring wellboresduring completion and production of wellbores, reservoir conditions,estimating quantities of hydrocarbons (oil and gas), operating downholedevices in the wellbores, and determining the physical condition of thewellbore and downhole devices.

Reservoir monitoring typically involves determining certain downholeparameters in producing wellbores at various locations in one or moreproducing wellbores in a field, typically over extended time periods.Wireline tools are most commonly utilized to obtain such measurements,which involves transporting the wireline tools to the wellsite,conveying the tools into the wellbores, shutting down the production andmaking measurements over extended periods of time and processing theresultant data at the surface. Seismic methods wherein a plurality ofsensors are placed on the earth's surface and a source placed at thesurface or downhole are utilized to provide maps of subsurfacestructure. Such information is used to update prior seismic maps tomonitor the reservoir or field conditions. Updating existing 3-D seismicmaps over time is referred to in industry as “4-D Seismic”. The abovedescribed methods are very expensive. The wireline methods are utilizedat relatively large time intervals, thereby not providing continuousinformation about the wellbore condition or that of the surroundingformations.

Placement of permanent sensors in the wellbore, such as temperaturesensors, pressure sensors, accelerometers and hydrophones has beenproposed to obtain continuous wellbore and formation information. Aseparate sensor is utilized for each type of parameter to be determined.To obtain such measurements from the entire useful segments of eachwellbore, which may have multi-lateral wellbores, requires using a largenumber of sensors, which requires a large amount of power, dataacquisition equipment and relatively large space in the wellbore: thismay be impractical or prohibitively expensive.

Once the information has been obtained, it is desirable to manipulatedownhole devices such as completion and production strings. Prior artmethods for performing such functions rely on the use of electricallyoperated devices with signals for their operation communicated throughelectrical cables. Because of the harsh operating conditions downhole,electrical cables are subject to degradation. In addition, due to longelectrical path lengths for downhole devices, cable resistance becomessignificant unless large cables are used. This is difficult to do withinthe limited space available in production strings. In addition, due tothe high resistance, power requirements also become large.

One particular arrangement in which operation of numerous downholedevices becomes necessary is in secondary recovery. Injection wellshave, of course, been employed for many years in order to flush residualoil in a formation toward a production well and increase yield from thearea. A common injection scenario is to pump steam down an injectionwell and into the formation which functions both to heat the oil in theformation and force its movement through the practice of steam flooding.In some cases, heating is not necessary as the residual oil is in aflowable form, however in some situations the oil is in such a viscousform that it requires heating in order to flow. Thus, by using steam oneaccomplishes both objectives of the injection well: 1) to force residualoil toward the production well and 2) to heat any highly viscous oildeposits in order mobilize such oil to flow ahead of the flood fronttoward the production well. As is well known to the art, one of the mostcommon drawbacks of employing the method above noted with respect toinjection wells is an occurrence commonly identified as “breakthrough”.Breakthrough occurs when a portion of the flood front reaches theproduction well. As happens the flood water remaining in the reservoirwill generally tend to travel the path of least resistance and willfollow the breakthrough channel to the production well. At this point,movement of the viscous oil ends. Precisely when and where thebreakthrough will occur depends upon water/oil mobility ratio, thelithology, the porosity and permeability of the formation as well as thedepth thereof. Moreover, other geologic conditions such as faults andunconformities also affect the in-situ sweep efficiency.

While careful examination of the formation by skilled geologists canyield a reasonable understanding of the characteristics thereof andtherefore deduce a plausible scenario of the way the flood front willmove, it has not heretofore been known to monitor precisely the locationof the flood front as a whole or as individual sections thereof. By somonitoring the flood front, it is possible to direct greater or lesserflow to different areas in the reservoir, as desired, by adjustment ofthe volume and location of both injection and production, hencecontrolling overall sweep efficiency.. By careful control of the floodfront, it can be maintained in a controlled, non fingered profile. Byavoiding premature breakthrough the flooding operation is effective formore of the total formation volume, and thus efficiency in theproduction of oil is improved.

In production wells, chemicals are often injected downhole to treat theproducing fluids. However, it can be difficult to monitor and controlsuch chemical injection in real time. Similarly, chemicals are typicallyused at the surface to treat the produced hydrocarbons (i.e., to breakdown emulsions) and to inhibit corrosion. However, it can be difficultto monitor and control such treatment in real time.

The present invention addresses the above-described deficiencies of theprior art and provides apparatus and methods which utilize sensors (suchas fiber optic sensors), wherein each sensor can provide informationabout more than one parameter to perform a variety of functions. Thesensors are used to measure parameters related to the chemicalintroduction in real time so that the chemical treatment system can beaccurately monitored and controlled.

The present invention addresses the above-described deficiencies ofprior art and provides apparatus and methods which utilize fiber opticsensors, wherein each sensor can provide information about more than oneparameter to perform a variety of functions. The sensors may be placedalong any length of the wellbore. Sensor segments, each containing oneor more sensors, may be coupled to form an active section that may bedisposed in the casing for continuous monitoring of the wellbore.Sensors may be distributed in a wellbore or multiple wellbores fordetermining parameters of interest. Hermetically sealed optical fiberscoated with high temperature resistant materials are commerciallyavailable. Single or multi-mode sensors can be fabricated along thelength of such optical fibers. Such sensors include temperature,pressure and vibration sensors. Such sensors can withstand hightemperatures in excess of 250 degrees Celsius for extended time periodsand thus have been found to be useful in wellbore applications. Anoptical fiber is a special case of an optical waveguide and in mostapplications, other types of optical waveguides, including thosecontaining a fluid, can usually be substituted for optical fiber.

The present invention provides certain completion and production stringsthat utilize fiber optical waveguide based sensors and devices. Theinvention also provides a method of generating electrical powerdownhole, utilizing light cells installed in the wellbore.

SUMMARY OF THE INVENTION

This invention uses fiber optic sensors to make measurements of downholeconditions in a producing borehole. The measurements include temperatureand pressure measurements; flow measurements related to the presence ofsolids and of corrosion, scale and paraffin buildup; measurements offluid levels; displacement; vibration; rotation; acceleration; velocity;chemical species; radiation; pH values; humidity; density; and ofelectromagnetic and acoustic wavefields. These measurements are used foractivating a hydraulically-operated device downhole and deploying afiber optic sensor line utilizing a common fluid conduit. A returnhydraulic conduit is placed along the length of a completion string. Thehydraulic conduit is coupled to the hydraulically-operated device in amanner such that when fluid under pressure is supplied to the conduit,it would actuate the device. The string is placed or conveyed in thewellbore. Fiber optic cable carrying a number of sensors is forced intoone end of the conduit until it returns at the surface at the other end.Light source and signal processing equipment is installed at thesurface. The fluid is supplied under sufficient pressure to activate thedevice when desired. The hydraulically-operated device may be a packer,choke, sliding sleeve, perforating device, flow control valve,completion device, an anchor or any other device. The fiber opticsensors carried by the cable may include pressure sensors, temperaturesensors, vibration sensors, and flow measurement sensors.

This invention also provides a method of controlling production from awellbore. A production string carrying an electrical submersible pump ispreferably made at the surface. An optical fiber carrying a plurality offiber optic sensors is placed along a high voltage line that suppliespower to the pump for taking measurements along the wellbore length. Inone configuration, a portion of the fiber carrying selected sensors isdeployed below the pump. Such sensors may include a temperature sensor,a pressure sensor and a flow rate measurement sensor. These sensorseffectively replace the instrumentation package usually installed forthe pump.

In an application to control of injection wells, the invention providessignificantly more information to well operators thus enhancing oilrecovery to a degree not heretofore known. This is accomplished byproviding real time information about the formation itself and the floodfront by providing permanent downhole sensors capable of sensing changesin the swept and unswept formation and/or the progression of the floodfront. Preferably a plurality of sensors would be employed to provideinformation about discrete portions of strata surrounding the injectionwell. This provides a more detailed data set regarding the well(s) andsurrounding conditions. The sensors are, preferably, connected to aprocessor either downhole or at the surface for processing ofinformation. Moreover, in a preferred embodiment the sensors areconnected to computer processors which are also connected to sensors ina production well (which are similar to those disclosed in U.S. Pat. No.5,597,042 which is fully incorporated herein by reference) to allow theproduction well to “talk” directly to the related injection well(s) toprovide an extremely efficient real time operation. Sensors employedwill be to sense temperature, pressure, flow rate, electrical andacoustic conductivity, density and to detect various light transmissionand reflection phenomena. All of these sensor types are availablecommercially in various ranges and sensitivities which are selectable byone of ordinary skill in the art depending upon particular conditionsknown to exist in a particular well operation. Specific pressuremeasurements will also include pressure(s) at the exit valve(s) down theinjection well and at the pump which may be located downhole or at thesurface. Measuring said pressure at key locations such as at the outlet,upstream of the valve(s) near the pump will provide information aboutthe speed, volume, direction, etc. at/in which the waterflood front (orother fluid) is moving. Large differences in the pressure from higher tolower over a short period of time could indicate a breakthrough.Conversely, pressure from lower to higher over short periods of timecould indicate that the flood front had hit a barrier. These conditionsare, of course, familiar to one of skill in the art but heretofore farless would have been known since no workable system for measuring theparameters existed. Therefore the present invention since it increasesknowledge, increases productivity.

Referring now to the measurement of density as noted above, the presentinvention uses fluid densities to monitor the flood front from thetrailing end. As will be appreciated from the detailed discussionherein, the interface between the flood front and the hydrocarbon fluidprovides an acoustic barrier from which a signal can be reflected. Thusby generating acoustic signals and mapping the reflection, the profileof the front is generated in 4D i.e., three dimensions over time.

The distributed sensors of this invention find particular utility in themonitoring and control of various chemicals which are injected into thewell. Such chemicals are needed downhole to address a large number ofknown problems such as for scale inhibition and various pretreatments ofthe fluid being produced. In accordance with the present invention, achemical injection monitoring and control system includes the placementof one or more sensors downhole in the producing zone for measuring thechemical properties of the produced fluid as well as for measuring otherdownhole parameters of interest. These sensors are preferably fiberoptic based and are formed from a sol gel matrix and provide a hightemperature, reliable and relatively inexpensive indicator of thedesired chemical parameter. The downhole chemical sensors may beassociated with a network of distributed fiber optic sensors positionedalong the wellbore for measuring pressure, temperature and/or flow.Surface and/or downhole controllers receive input from the severaldownhole sensors, and in response thereto, control the injection ofchemicals into the borehole.

In still another feature of this invention, parameters related to thechemical being used for surface treatments are measured in real time andon-line, and these measured parameters are used to control the dosage ofchemicals into the surface treatment system.

Another aspect of the present invention provides a fiber optic device(light actuated transducer) for generating mechanical energy and methodsof using such energy at the well site. The device contains a fluid thatrapidly expands in an enclosure upon the application of optical energy.The expansion of the fluid moves a piston in the enclosure. The fluidcontracts and the piston is pushed back to its original position by aforce device such as spring. The process is then repeated to generatereciprocating motion of a member attached to the piston. The device islike an internal combustion engine wherein the fuel is a fluid in asealed chamber that expands rapidly when high energy light such as laserenergy is applied to the fluid. The energy generated by the opticaldevice is utilized to operate a device in the wellbore. The downholedevice may be any suitable device, including a valve, fluid controldevice, packer, sliding sleeve, safety valve, and an anchor. The motionenergy generated by the fiber optic devices may be used to operate agenerator to generate electrical power downhole which power is thenutilized to charge batteries downhole or to directly operate a downholedevice and/or to provide power to sensors in the wellbore. A pluralityof such fiber optic devices may be utilized to increase the energygenerated. The devices may also be used as a pump to control the supplyof fluids and chemicals in the wellbore.

Examples of the more important features of the invention have beensummarized rather broadly in order that the detailed description thereofthat follows may be better understood, and in order that thecontributions to the art may be appreciated. There are, of course,additional features of the invention that will be described hereinafterand which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present invention, reference shouldbe made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

FIG. 1 shows a schematic illustration of an elevational view of amulti-lateral wellbore and placement of fiber optic sensors therein.

FIG. 1A shows the use of a robotic device for deployment of the fiberoptic sensors.

FIG. 2 is a schematic illustration of a wellbore system wherein a fluidconduit along a string placed in the wellbore is utilized for activatinga hydraulically-operated device and for deploying a fiber optic cablehaving a number of sensors along its length according to one preferredembodiment of the present invention.

FIG. 3 shows a schematic diagram of a producing well wherein a fiberoptic cable with sensors is utilized to determine the health of downholedevices and to make measurements downhole relating to such devices andother downhole parameters.

FIG. 4 is a schematic illustration of a wellbore system wherein apermanently installed electrically-operated device is operated by afiber optic based system.

FIG. 5 is a schematic representation of an injection well illustrating aplurality of sensors mounted therein.

FIG. 6 is a schematic representation illustrating both an injection welland a production well having sensors and a flood front running betweenthe wells.

FIG. 7 is a schematic representation similar to FIG. 6 but illustratingfluid loss through unintended fracturing.

FIG. 8 is a schematic representation of an injection production wellsystem where the wells are located on either side of a fault.

FIG. 9 is a schematic illustration of a chemical injection monitoringand control system utilizing a distributed sensor arrangement anddownhole chemical monitoring sensor system in accordance with thepresent invention.

FIG. 10 is a schematic illustration of a fiber optic sensor system formonitoring chemical properties of produced fluids.

FIG. 11 is a schematic illustration of a fiber optic sol gel indicatorprobe for use with the sensor system of FIG. 10.

FIG. 12 is a schematic illustration of a surface treatment system inaccordance with the present invention.

FIG. 13 is a schematic of a control and monitoring system for thesurface treatment system of FIG. 12.

FIG. 14 is a schematic illustration of a wellbore system whereinelectric power is generated downhole utilizing a light cell for use inoperating sensors and devices downhole.

FIGS. 15 and 15A-15C show the power section of fiber optic devices foruse in the system of FIG. 1.

FIG. 16 is a schematic illustration of a wellbore with a completionstring having a fiber optic energy generation device for operating aseries of devices downhole.

FIGS. 17A-17C show certain configurations for utilizing the fiber opticdevices to produce the desired energy.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The various concepts of the present invention will be described inreference to FIGS. 1-17, which show a schematic illustrations ofwellbores utilizing fiber optic-based sensors and operating devices.

FIG. 1 shows an exemplary main or primary wellbore 12 formed from theearth surface 14 and lateral wellbores 16 and 18 formed from the mainwellbore 18. For the purpose of explanation, and not as any limitation,the main wellbore 18 is partially formed in a producing formation or payzone I and partially in a non-producing formation or dry formation II.The lateral wellbore 16 extends from the main wellbore at a juncture 22into the producing formation I, while the lateral wellbore 16 extendsfrom the main wellbore 12 at juncture 24 into a second producingformation III. For the purposes of this illustration only, the wellboresherein are shown as being drilled on land; however, this invention isequally applicable to offshore wellbores. It should be noted that allwellbore configurations shown and described herein are to illustrate thepresent invention and are not be construed to limit the inventionsclaimed herein.

In one application, a number of fiber optic sensors 40 are placed in thewellbore 12. A single or a plurality of fiber optic strings or segments,each such segment containing a plurality of spaced apart fiber opticsensors 40 may be used to install the desired number of fiber opticsensors 40 in the wellbore 12. As an example, FIG. 1 shows two seriallycoupled segments 41 a and 41 b, each containing a plurality of spacedapart fiber optic sensors 40. A light source and detector (LS/D) 46 acoupled to an end 49 segment 41 a is disposed in the wellbore 12 totransmit light energy to sensors 40 and to receiver signals from thesensors 40. A data acquisition unit (DA) 48 a is disposed downhole tocontrol the operation of the sensors 40, process downhole sensor signalsand data, and to communicate with other equipment and devices, includingdevices in the wellbores or at the surface shown below in FIGS. 2-17.

Alternatively, a light source 46 b and the data acquisition andprocessing unit 48 b may be placed on the surface 14. Similarly, fiberoptic sensor strings 45 may be disposed in other wellbores in thesystem, such as wellbores 16 and wellbore 18. A single light source,such as light source 46 a or 46 b may be used for all fiber opticsensors int he various wellbores, such as shown by the dotted line 70.Alternatively, multiple sources and data acquisition units may be useddownhole, at the surface, or in combination. Since the same sensor maymake different types of measurements, the data acquisition unit 48 a or48 b is programmed to multiplex the measurements. Multiplexingtechniques are well known in the art and are thus not described indetail herein. The data acquisition unit 46 a may be programmed tocontrol the downhole sensors autonomously or upon receiving commandsignals from the surface or a combination of these methods.

The sensors 40 may be installed in the wellbores 12, 16 and 18 before orafter installing casings in the wellbores, such as casings 52 showninstalled in the wellbore 12. This may be accomplished by connecting thestrings 41 a and 41 b along the inside casings 52. In such a method, thestrings 41 a and 41 b are preferably connected end-to-end at the surfaceto ensure proper connections of the couplings 42. The fiber opticsensors 40 and/or strings 41 a and 41 b may be deployed or installed byconveying on coil tubing or pipes or other known methods. Alternatively,the fiber optic sensors may be conveyed and installed by roboticsdevices. This is illustrated in FIG. 1A where a robotic device 62 isshown with a string of sensors 64 attached to it. The robotic deviceproceeds down the wellbore 12 having a casing 52 therein to the positionindicated by 62′, deploying the string of sensors in the positionindicated by 64′. In addition to installing sensors, the robotic device64 may also perform other functions, such as monitoring the performanceof the sensors, and communicating with other devices such as the DA, theLS/D and other downhole devices described below. The robotic devices mayalso be utilized to replace a sensor, conduct repairs and to retrievethe sensors or strings to the surface. Alternatively, the fiber opticsensors 40 may be placed in the casing 52 at the surface whileindividual casing sections (which are typically about forty feet long)are joined prior to conveying the casing sections into the borehole.Stabbing techniques for joining casing or tubing sections are known inthe art and are preferred over rotational joints because stabbinggenerally provides better alignment of the end couplings 42 and alsobecause it allows operators to test and inspect optical connectionsbetween segments for proper two-way transmission of light energy throughthe entire string 41.

In the system shown in FIG. 1, a plurality of fiber optic sensors 40 areinstalled spaced apart in one or more wellbores, such as wellbores 12,16 and 18. If desired, each fiber optic sensor can operate in more thanone mode to provide a number of different measurements. The light source46 a, and dat detection and acquisition system 48 a are preferablyplaced downhole. Although each fiber optic sensor 40 providesmeasurements for multiple parameters, it is relatively small compared toindividual commonly used single measurement sensors, such as pressuresensors, strain gauges, temperature sensors, flow measurement devicesand acoustic sensors. This makes it possible to make a large number ofdifferent types of measurements utilizing relatively little spacedownhole. Installing data acquisition and processing devices or units 48a downhole allows making a large number of data computations andprocessing downhole, avoiding the need for transmitting large amounts ofdata to the surface. Installing the light source 46 a downhole allowslocating the source 46 a close to the sensors 40, which avoidstransmission of light over great distances from the surface. The datafrom the downhole acquisition system 48 a may be transmitted to thesurface by any suitable method including wireline connectors,electromagnetic telemetry, and acoustic methods. Still, in someapplications, it may be desirable to locate the light source 46 b and/orthe data acquisition and processing system 46 b at the surface. Also, insome cases, it may be more advantageous to partially process the datadownhole and partially at the surface.

Still referring to FIG. 1, any number of other sensors, generallydenoted herein by numeral 60 may be disposed in any of the wellbores 12,16 and 18. Such sensors may include sensors for determining theresistivity of fluids and formations, gamma ray sensors, andhydrophones. The measurements from the fiber optic sensors 40 andsensors 60 are combined to determine the various conditions downhole.For example, flow measurements from production zones and the resistivitymeasurements may be combined to determine water saturation or todetermine oil, gas and water content.

In one mode, the fiber optic sensors are permanently installed in thewellbores at selected locations. In a producing wellbore, the sensors 40continuously or periodically (as programmed) provide the pressure and/ortemperature and/or fluid flow measurements. Such measurements arepreferably made for each producing zone in each of the wellbores. Toperform certain types of reservoir analyses, it is required to know thetemperature and pressure build rates in the wellbores. This requiresmeasuring temperature and pressure at selected locations downhole overextended time periods after shutting down the well at the surface. Inprior art methods, the well is shut down, a wireline tool is conveyedinto the wellbore and positioned at one location in the wellbore. Thetool continuously measures temperature and pressure and may provideother measurements, such as flow rates. These measurements are thenutilized to perform reservoir analysis, which may included determiningthe extent of the hydrocarbon reserves remaining in a field, flowcharacteristics of the fluid from the producing formation, watercontent, etc. The above described prior art methods do not providecontinuous measurements while the well is producing and require specialwireline tools to be conveyed into the borehole. The present invention,on the other hand, provides, in-situ measurements while the well isproducing. The fluid flow information from each zone is used todetermine the effectiveness of each producing zone. Decreasing flowrates over time indicate problems with the flow control devices, such asscreens and sliding sleeves, or clogging of the perforations and rockmatrix near the wellbore. This information is used to determine thecourse of action, which may include further opening or closing slidingsleeves to increase or decrease production rates, remedial work, such ascleaning or reaming operations, shutting down a particular zone, etc.This is discussed below in reference to FIGS. 2-13. The temperature andpressure measurements are used to continually monitor each productionzone and to update reservoir models. To make measurements determiningthe temperature and pressure buildup rates, the wellbores are shut downand the process of making measurements continues. This does not requiretransporting wireline tools to the location, something that can be veryexpensive at offshore locations and wellbores drilled in remotelocations. Furthermore, in-situ measurements and computed data can becommunicated to a central office or the offices of the logging andreservoir engineers via satellite. This continuous monitoring ofwellbores allows taking relatively quick action, which can significantlyimprove the hydrocarbon production and the life of the wellbore. Theabove described methods may also be taken for non-producing zones, suchas zone II, to aid in reservoir modeling, to determine the effect ofproduction from various wellbores on the field in which the wellboresare being drilled.

FIG. 2 is a schematic diagram of a wellbore system 100 according to oneembodiment of the present invention. System 100 includes a wellbore 102having a surface casing 101 installed a short distance from the surface104. After the wellbore 102 has been drilled to a desired depth. Acompletion or production string 106 is conveyed into the wellbore 102.The string 106 includes at least one downhill hydraulically operabledevice 114 carried by a tubing 108 which tubing may be a drill pipe,coiled tubing or production tubing. A fluid conduit 110 having a desiredinner diameter 111 is placed or attached either on the outside of thestring 106 (as shown in FIG. 2) or in the inside of the string (notshown). The conduit 110 is routed at a desired location on the string106 via a u-joint 112 so as to provide a smooth transition for returningthe conduit 110 to the surface 104. A hydraulic connection 124 isprovided from the conduit 110 to the device 114 so that a fluid underpressure can pass from the conduit 110 to the device 114.

After the string 106 has been placed or installed at a desired depth inthe wellbore 102, an optical fiber 112 is pumped inlet 130 a underpressure by a source of fluid 130.

The optical fiber 122 passes through the entire length of the conduit110 and returns to the surface 104 via outlet 130 b. The fiber 122 isthen optically coupled to a light source and recorder (or detector)(LS/REC) 140. A data acquisition/signal processor (DA/SP) 142 processesdata/signal received via the optical fiber 122 and also controls theoperation of the light source and recorder 140.

The optical fiber 122 includes a plurality of sensors 120 distributedalong its length. Sensors 120 may include temperature sensors, pressuresensors, vibration sensors or any other fiber optic sensor that can beplaced on the fiber optic cable 122. Sensors 120 are formed into thecable during the manufacturing of the cable 122. The downhole device 114may be any downhole fluid-activated device and may be a valve, a slidingsleeve, a perforating device, a packer or any otherhydraulically-activated device. The downhill device is activated bysupplying fluid under pressure through the conduit 110. Details of thesensor arrangement were described above with reference to FIGS. 1-1A.

Thus, the system 100 includes a hydraulic-control line in conduit 110carried on a string 106. The control line 110 receives fiber optic cable122 throughout its length and is connected to surface instrumentation140 and 142 for distributed measurements of downhole parameters alongits length, such as temperature, pressure, etc. The conduit 106 alsocarries fluid under pressure from a source of fluid under pressure 130for operating a fluid-actuated device 114 such as a sliding sleeve,connected to the line 110. The line 110 may be arranged downhole alongthe string 106 in a V or other convenient shape. The fluid-actuateddevice 114 may also be a choke, fluid flow regulation device, packer,perforating gun or other completion and or production device.

During the completion of the wellbore 102, the sensors 120 provideuseful measurements relating to their associated downhole parameters andthe line 106 is used to actuate a downhole device. The sensors 120continue to provide information about the downhole parameters over time,as discussed above with reference to FIGS. 1-1A.

Another part of the invention is related to the control of downholedevices using optical fibers. FIG. 2 shows a schematic diagram of aproducing well 202 that preferably with two electric submersible pumps(“ESP”) 214 one for pumping the oil/gas 206 the surface 203 and theother to pump any separated water back into a formation. The formationfluid 206 flows from a producing zone 208 into the wellbore 202 viaperforations 207. Packers 210 a and 210 b installed below and above theESP 214 force the fluid 206 to flow to the surface 203 via pumps ESP214. An oil water separator 250 separates the oil and water and providethem to their respective pumps 214 a-214 b. A choke 252 provides desiredback pressure. An instrument package 260 and pressure sensor isinstalled in the pump string 218 to measure related parameters duringproduction. The present invention utilizes optical fiber with embeddedsensors to provide measurements of selected parameters, such astemperature, pressure, vibration, flow rate as described below. ESPs 214run at very high voltage which is supplied from a high voltage source230 at the surface via a high voltage cable 224. Due to the high powercarried by the cable 224, electrical sensors are generally not placed onor along side the cable 224.

In one embodiment of the present invention as shown in FIG. 3, a fiberoptic cable 222 carrying sensors 220 is placed along the power cable224. The fiber optic cable 222 is extended to below the ESPs 214 to thesensors in the instrumentation package 260 and to provide control to thedevices, if desired. In one application, the sensors 220 measurevibration and temperature of the ESP 214. It is desirable to operate theESP at a low temperature and without excessive vibration. The ESP 214speed is adjusted so as to maintain one or both such parameters belowtheir predetermined maximum value or within their respectivepredetermined ranges. The fiber optic sensors are used in thisapplication to continuously or periodically determine the physicalcondition (health) of the ESP. The fiber optic cable 222 may be extendedor deployed below the ESP at the time of installing the productionstring 218 in the manner described with respect to FIG. 2. Such aconfiguration may be utilized to continuously measure downhillparameters, monitor the health of downhill devices and control downhilldevices.

FIG. 4 shows a schematic of a wellbore system 400 wherein a permanentlyinstalled electrically-operated device is operated by a fiber opticbased system. The system 400 includes a wellbore 402 and anelectrically-operated device 404 installed at a desired depth, which maybe a sliding sleeve, a choke, a fluid flow control device etc. Anelectric control unit 406 controls the operation of the device 404. Aproduction tubing 410 installed above the device 404 allows formationfluid to flow to the surface 401. During the manufacture of the string411 that includes the device 404 and the tubing 410, a conduit 422 isclamped along the length of the tubing 410 with clamps 423. An opticalcoupler 407 is provided at the electrical control unit 406 which canmate with a coupler fed through the conduit 422.

Either prior to or after placing the string 410 in the wellbore 402, afiber optic cable 421 is deployed in the conduit 422 so that a coupler422 a at the cable 421 end would couple with the coupler 407 of thecontrol unit 406. A light source 440 provides the light energy to thefiber 422. A plurality of sensors 420 may be deployed along the fiber422 as described before. A sensor preferably provided on the fiber 422determines the flow rate of formation fluid 414 flowing through thedevice 404. Command signals are sent by DA/SP 442 to activate the device404 via the fiber 422. These signals are detected by the control unit406, which in turn operate the device 404. This, in the configuration ofFIG. 4, fiber optics is used to provide two way communication betweendownhole devices and sensors and a surface unit and to operate downholedevices.

A particular application of the invention is in the control of downholedevices in secondary recovery operations. Referring to FIG. 5, one ofordinary skill in the art will appreciate a schematic representation ofan injection well 510. Also recognizable will be the representation of aflood front 520 which emanates from the injection well and is intendedto progress toward a production well. This is also well represented inFIG. 6 of the present application. In the present invention at least oneand, preferably, a plurality of sensors 512 are located permanentlyinstalled in the injection well and which are connected via theelectrical wire cabling or fiber optic cabling to a processor which mayeither be a permanent downhole processor or a surface processor. Thesystem provides immediate real time information regarding the conditionof the fluid front having been injected into the formation by theinjection well. By carefully monitoring parameters such as conductivity,fluid density, pressure at the injection ports 514 or at the pump 516(which while represented at the surface can be positioned downhole aswell), acoustics and fluorescence for biological activity, one canascertain significant information about the progress of the flood frontsuch as whether the front has hit a barrier or whether the front mayhave “fingered” resulting in a likely premature breakthrough. Thisinformation is extremely valuable to the operator in order to allowremedial measures to prevent occurrences that would be detrimental tothe efficiency of the flooding operation. Remedial actions include theopening or closing of chokes or other valves in increments or completelyin order to slow down particular areas of injection or increase thespeed of particular areas of injection in order to provide the mostuniform flood front based upon the sensed parameters. These remedialmeasures can be taken either by personnel at the surface directing suchactivity or automatically upon command by the surfacecontroller/processor on downhole processing unit 518. The sensorscontemplated herein may be in the injection well or in both theinjection well and the production well. They are employed in severaldifferent methods to obtain information such as that indicated above.

Control is further heightened in an alternate embodiment by providing alink between downhole sensors in the production well to the downholesensors in the injection well as well as a connection to the flowcontrol tools in both wells. By providing the operable connections toall of these parts of the system the well can actually run itself andprovide the most efficient oil recovery based upon the creation andmaintenance of a uniform flood front. It will be understandable at thispoint to one of ordinary skill in the art that the flood front can beregulated from both sides of FIG. 2 i.e., the injection well and theproduction well by opening production well valves in areas where theflood front is lagging while closing valves in areas where the floodfront is advancing.

Complementary to this, the fluid injection valves e.g., sliding orrotating sleeves, etc. would be choked or closed where the flood frontis advancing quickly and opened more where the flood front is advancingslowly. This seemingly complex set of circumstances is easily controlledby the system of the invention and rapidly remedies any abnormalities inthe intended flood profile. Sweep efficiency of the steam or other fluidfront is greatly enhanced by the system of the invention. All of thesensors contemplated in the production well and the injection well are,preferably, permanently installed downhole sensors which are connectedto processors and/to one another by electrical cabling or fiber opticcabling.

In another embodiment of the invention, illustrated schematically inFIG. 7, downhole sensors measure strain induced in the formation by theinjected fluid. Strain is an important parameter for avoiding exceedingthe formation parting pressure or fracture pressure of the formationwith the injected fluid. By avoiding the opening of or widening ofnatural pre-existing fractures large unswept areas of the reservoir canbe avoided. The reason this information is important in the regulationof pressure of the fluid to avoid such activity is that when pressureopens fractures or new fractures are created there is a path of muchless resistance for the fluid to run through. Thus as stated earlier,since the injection fluid will follow the path of least resistance itwould generally run in the fractures and around areas of the reservoirthat need to be swept. Clearly this substantially reduces itsefficiency. The situation is generally referred to in the art as an“artificially high permeability channel.” Another detriment to such acondition is the uncontrolled loss of injected fluids. This is clearly aloss of oil due to the reduced efficiency of the sweep and additionallymay function as an economic drain due to the loss of expensive fluids.

FIG. 7 schematically illustrates the embodiment and the condition setforth above by illustrating an injection well 550 and a production well560. Fluid 552 is illustrated escaping via the unintended fracture fromthe formation 554 into the overlying gas cap level 556 and theunderlying water table 561 and it is evident to one of ordinary skill inthe art that the fluid is being lost in this location. The condition isavoided by the invention by using pressure sensors to limit theinjection fluid pressure as described above. The rest of the fluid 552is progressing as it is intended to through the formation 554. In orderto easily and reliably determine what the stress is in the formation554, acoustic sensors 556 are located in the injection well 550 atvarious points therein. Acoustic sensors which are well suited to thetask to which they will be put in the present invention are commerciallyavailable from Systems Innovations, Inc., Spectris Corporation andFalmouth Scientific, Inc. The acoustic sensors pick up sounds generatedby stress in the formation which propagate through the reservoir fluidsor reservoir matrix to the injection well. In general, higher soundlevels would indicate severe stress in the formation and should generatea reduction in pressure of the injected fluid whether by automaticcontrol or by technician control. A data acquisition system 558 ispreferable to render the system extremely reliable and system 558 may beat the surface where it is illustrated in the schematic drawing or maybe downhole. Based upon acoustic signals received the system of theinvention, preferably automatically, although manually is workable,reduces pressure of the injected fluid by reducing pump pressure.Maximum sweep efficiency is thus obtained.

In yet another embodiment of the invention, as schematically illustratedin FIG. 8, acoustic generators and receivers are employed to determinewhether a formation which is bifurcated by a fault is sealed along thefault or is permeable along the fault. It is known by one of ordinaryskill in the art that different strata within a formation bifurcated bya fault may have some zones that flow and some zones that are sealed;this is the illustration of FIG. 8. Referring directly to FIG. 8,injection well 570 employs a plurality of sensors 572 and acousticgenerators 574 which, most preferably, alternate with increasing depthin the wellbore. In production well 580, a similar arrangement ofsensors 572 and acoustic generators 574 are positioned. The sensors andgenerators are preferably connected to processors which are eitherdownhole or on the surface and preferably also connect to the associatedproduction or injection well. The sensors 572 can receive acousticsignals that are naturally generated in the formation, generated byvirtue of the fluid flowing through the formation from the injectionwell and to the production well and also can receive signals which aregenerated by signal generators 574. Where signal generators 574 generatesignals, the reflected signals that are received by sensors 572 over aperiod of time can indicate the distance and acoustic volume throughwhich the acoustic signals have traveled. This is illustrated in area Aof FIG. 8 in that the fault line 575 is sealed between area A and area Bon the figure. This is illustrated for purposes of clarity only byproviding circles 576 along fault line 575. Incidentally, the areas offault line 575 which are permeable are indicated by hash marks 577through fault line 575. Since the acoustic signal represented by arrowsand semi-curves and indicated by numeral 578 cannot propagate throughthe area C of the drawing which bifurcates area A from area B on theleft side of the drawing, that signal will bounce and it then can bepicked up by sensor 572. The time delay, number and intensity ofreflections and mathematical interpretation which is common in the artprovides an indication of the lack of pressure transmissivity betweenthose two zones. Additionally this pressure transmissivity can beconfirmed by the detection by said acoustic signals by sensors 572 inthe production well 580. In the drawing the area directly beneath area Ais indicated as area E is permeable to area B through fault 575 becausethe region D in that area is permeable and will allow flow of the floodfront from the injection well 570 through fault line 575 to theproduction well 580. Acoustic sensors and generators can be employedhere as well since the acoustic signal will travel through the area Dand, therefore, reflection intensity to the receivers 572 will decrease.Time delay will increase. Since the sensors and generators are connectedto a central processing unit and to one another it is a simple operationto determine that the signal, in fact, traveled from one well to theother and indicates permeability throughout a particular zone. Byprocessing the information that the acoustic generators and sensors canprovide the injection and production wells can run automatically bydetermining where fluids can flow and thus opening and closing valves atrelevant locations on the injection well and production well in order toflush production fluid in a direction advantageous to run through a zoneof permeability along the fault.

Other information can also be generated by this alternate system of theinvention since the sensors 572 are clearly capable of receiving notonly the generated acoustic signals but naturally occurring acousticwaveforms arising from both the flow of the injected fluids as theinjection well and from those arising within the reservoirs in result ofboth fluid injection operations and simultaneous drainage of thereservoir in resulting production operations. The preferred permanentdeployment status of the sensors and generators of the invention permitand see to the measurements simultaneously with ongoing injectionflooding and production operations. Advancements in both acousticmeasurement capabilities and signal processing while operating theflooding of the reservoir represents a significant, technologicaladvance in that the prior art requires cessation of the injection/production operations in order to monitor acoustic parameters downhole.As one of ordinary skill in the art will recognize the cessation ofinjection results in natural redistribution of the active flood profiledue primarily to gravity segregation of fluids and entropic phenomenathat are not present during active flooding operations. This clearlyalso enhances the possibility of premature breakthrough, as oil migratesto the relative top of the formation and the injected fluid, usuallywater, migrates to the relative bottom of the formation, there is asignificant possibility that the water will actually reach theproduction well and thus further pumping of steam or water will merelyrun underneath the layer of oil at the top of the formation and thesweep of that region would be extremely difficult thereafter.

In yet another embodiment of the invention fiber optics are employed(similar to those disclosed in the U.S. application Ser. No. 60/048,989filed on Jun. 9, 1997(which is fully incorporated herein by reference)to determine the amount of and/or presence of biofouling within thereservoir by providing a culture chamber within the injection orproduction well, wherein light of a predetermined wavelength may beinjected by a fiber optical cable, irradiating a sample determining thedegree to which biofouling may have occurred. As one of ordinary skillin the art will recognize, various biofouling organisms will have theability to fluoresce at a given wavelength, that wavelength oncedetermined, is useful for the purpose above stated.

In another embodiment of the invention, the flood front is monitoredfrom the “back” employing sensors installed in the injection well. Thesensors which are adequately illustrated in FIGS. 5 and 6 provideacoustic signals which reflect from the water/oil interface thusproviding an accurate picture in a moment in time of thethree-dimensional flood front. Taking pictures in 4-D i.e., threedimensions over real time provides an accurate format of the densityprofile of the formation due to the advancing flood front. Thus, aparticular profile and the relative advancement of the front can beaccurately determined by the density profile changes. It is certainlypossible to limit the sensors and acoustic generators to the injectionwell for such a system, however it is even more preferable to alsointroduce sensors and acoustic generators in the production well towardwhich the front is moving thus allowing an immediate double check of thefluid front profile. That is, acoustic generators on the production wellwill reflect a signal off the oil/water interface and will provide anequally accurate three-dimensional fluid front indicator. The indicatorsfrom both sides of the front should agree and thus provides an extremelyreliable indication of location and profile.

Referring now to FIG. 9, the distributed fiber optic sensors of the typedescribed above are also well suited for use in a production well wherechemicals are being injected therein and there is a resultant need forthe monitoring of such a chemical injection process so as to optimizethe use and effect of the injected chemicals. Chemicals often need to bepumped down a production well for inhibiting scale, paraffins and thelike as well as for other known processing applications and pretreatmentof the fluids being produced. Often, as shown in FIG. 9, chemicals areintroduced in an annulus 600 between the production tubing 602 and thecasing 604 of a well 606. The chemical injection (shown schematically at608) can be accomplished in a variety of known methods such as inconnection with a submersible pump (as shown for example in U.S. Pat.No. 4,582,131, assigned to the assignee hereof and incorporated hereinby reference) or through an auxiliary line associated with a cable usedwith an electrical submersible pump (such as shown for example in U.S.Pat. No. 5,528,824, assigned to the assignee hereof and incorporatedherein by reference).

In accordance with an embodiment of the present invention, one or morebottomhole sensors 610 are located in the producing zone for sensing avariety of parameters associated with the producing fluid and/orinteraction of the injected chemical and the producing fluid. Thus, thebottomhole sensors 610 will sense parameters relative to the chemicalproperties of the produced fluid such as the potential ionic content,the covalent content, pH level, oxygen levels, organic precipitates andlike measurements. Sensors 610 can also measure physical propertiesassociated with the producing fluid and/or the interaction of theinjected chemicals and producing fluid such as the oil/water cut,viscosity and percent solids. Sensors 610 can also provide informationrelated to paraffin and scale build-up, H₂S content and the like.

Bottomhole sensors 610 preferably communicate with and/or are associatedwith a plurality of distributed sensors 612 which are positioned alongat least a portion of the wellbore (e.g., preferably the interior of theproduction tubing) for measuring pressure, temperature and/or flow rateas discussed above in connection with FIG. 1. The present invention isalso preferably associated with a surface control and monitoring system614 and one or more known surface sensors 615 for sensing parametersrelated to the produced fluid; and more particularly for sensing andmonitoring the effectiveness of treatment rendered by the injectedchemicals. The sensors 615 associated with surface system 614 can senseparameters related to the content and amount of, for example, hydrogensulfide, hydrates, paraffins, water, solids and gas.

Preferably, the production well disclosed in FIG. 9 has associatedtherewith a so-called “intelligent” downhole control and monitoringsystem which may include a downhole computerized controller 618 and/orthe aforementioned surface control and monitoring system 614. Thiscontrol and monitoring system is of the type disclosed in U.S. Pat. No.5,597,042, which is assigned to the assignee hereof and fullyincorporated herein by reference. As disclosed in U.S. Pat. No.5,597,042, the sensors in the “intelligent” production wells of thistype are associated with downhole computer and/or surface controllerswhich receive information from the sensors and based on thisinformation, initiate some type of control for enhancing or optimizingthe efficiency of production of the well or in some other way effectingthe production of fluids from the formation. In the present invention,the surface and/or downhole computers 614, 618 will monitor theeffectiveness of the treatment of the injected chemicals and based onthe sensed information, the control computer will initiate some changein the manner, amount or type of chemical being injected. In the systemof the present invention, the sensors 610 and 612 may be connectedremotely or in-situ.

In a preferred embodiment of the present invention, the bottomholesensors comprise fiber optic chemical sensors. Such fiber optic chemicalsensors preferably utilize fiber optic probes which are used as a sampleinterface to allow light from the fiber optic to interact with theliquid or gas stream and return to a spectrometer for measurement. Theprobes are typically composed of sol gel indicators. Sol gel indicatorsallow for on-line, real time measurement and control through the use ofindicator materials trapped in a porous, sol gel derived, glass matrix.Thin films of this material are coated onto optical components ofvarious probe designs to create sensors for process and environmentalmeasurements. These probes provide increased sensitivity to chemicalspecies based upon characteristics of the specific indicator. Forexample, sol gel probes can measure with great accuracy the pH of amaterial and sol gel probes can also measure for specific chemicalcontent. The sol gel matrix is porous, and the size of the pores isdetermined by how the glass is prepared. The sol gel process can becontrolled so as to create a sol gel indicator composite with poressmall enough to trap an indicator in the matrix but large enough toallow ions of a particular chemical of interest to pass freely in andout and react with the indicator. An example of suitable sol gelindicator for use in the present invention is shown in FIGS. 10 and 11.

Referring to FIGS. 10 and 11, a probe is shown at 616 connected to afiber optic cable 618 which is in turn connected both to a light source620 and a spectrometer 622. As shown in FIG. 11, probe 616 includes asensor housing 624 connected to a lens 626. Lens 626 has a sol gelcoating 628 thereon which is tailored to measure a specific downholeparameter such as pH or is selected to detect the presence, absence oramount of a particular chemical such as oxygen, H₂S or the like.Attached to and spaced from lens 626 is a mirror 630. During use, lightfrom the fiber optic cable 618 is collimated by lens 626 whereupon thelight passes through the sol gel coating 628 and sample space 632. Thelight is then reflected by mirror 630 and returned to the fiber opticalcable. Light transmitted by the fiber optic cable is measured by thespectrometer 622. Spectrometer 622 (as well as light source 620) may belocated either at the surface or at some location downhole. Based on thespectrometer measurements, a control computer 614, 616 will analyze themeasurement and based on this analysis, the chemical injection apparatus608 will change the amount (dosage and concentration), rate or type ofchemical being injected downhole into the well. Information from thechemical injection apparatus relating to amount of chemical left instorage, chemical quality level and the like will also be sent to thecontrol computers. The control computer may also base its controldecision on input received from surface sensor 615 relating to theeffectiveness of the chemical treatment on the produced fluid, thepresence and concentration of any impurities or undesired byproducts andthe like.

In addition to the bottomhole sensors 610 being comprised of the fiberoptic sol gel type sensors, in addition, the distributed sensors 612along production tubing 602 may also include the fiber optic chemicalsensors (sol gel indicators) of the type discussed above. In this way,the chemical content of the production fluid may be monitored as ittravels up the production tubing if that is desirable.

The permanent placement of the sensors 610, 612 and control system 617downhole in the well leads to a significant advance in the field andallows for real time, remote control of chemical injections into a wellwithout the need for wireline device or other well interventions.

In accordance with the present invention, a novel control and monitoringsystem is provided for use in connection with a treating system forhandling produced hydrocarbons in an oilfield. Referring to FIG. 12, atypical surface treatment system used for treating produced fluid in oilfields is shown. As is well known, the fluid produced from the wellincludes a combination of emulsion, oil, gas and water. After these wellfluids are produced to the surface, they are contained in a pipelineknown as a “flow line”. The flow line can range in length from a fewfeet to several thousand feet. Typically, the flow line is connecteddirectly into a series of tanks and treatment devices which are intendedto provide separation of the water in emulsion from the oil and gas. Inaddition, it is intended that the oil and gas be separated for transportto the refinery.

The produced fluids flowing in the flow line and the various separationtechniques which act on these produced fluids lead to serious corrosionproblems. Presently, measurement of the rate of corrosion on the variousmetal components of the treatment systems such as the piping and tanksis accomplished by a number of sensor techniques including weight losscoupons, electrical resistance probes, electrochemical—linearpolarization techniques, electrochemical noise techniques and ACimpedance techniques. While these sensors are useful in measuring thecorrosion rate of a metal vessel or pipework, these sensors do notprovide any information relative to the chemicals themselves, that isthe concentration, characterization or other parameters of chemicalsintroduced into the treatment system. These chemicals are introduced fora variety of reasons including corrosion inhibition and emulsionbreakdown, as well as scale, wax, asphaltene, bacteria and hydratecontrol.

In accordance with an important feature of the present invention,sensors are used in chemical treatment systems of the type disclosed inFIG. 12 which monitors the chemicals themselves as opposed to theeffects of the chemicals (for example, the rate of corrosion). Suchsensors provide the operator of the treatment system with a real timeunderstanding of the amount of chemical being introduced, the transportof that chemical throughout the system, the concentration of thechemical in the system and like parameters. Examples of suitable sensorswhich may be used to detect parameters relating to the chemicalstraveling through the treatment system include the fiber optic sensordescribed above with reference to FIGS. 10 and 11 as well as other knownsensors such as those sensors based on a variety of technologiesincluding ultrasonic absorption and reflection, laser-heated cavityspectroscopy (LIMS), X-ray fluorescence spectroscopy, neutron activationspectroscopy, pressure measurement, microwave or millimeter wave radarreflectance or absorption, and other optical and acoustic (i.e.,ultrasonic or sonar) methods. A suitable microwave sensor for sensingmoisture and other constituents in the solid and liquid phase influentand effluent streams is described in U.S. Pat. No. 5,455,516, all of thecontents of which are incorporated herein by reference. An example of asuitable apparatus for sensing using LIBS is disclosed in U.S. Pat. No.5,379,103 all of the contents of which are incorporated herein byreference. An example of a suitable apparatus for sensing LIMS is theLASMA Laser Mass Analyzer available from Advanced Power Technologies,Inc. of Washington, D.C. An example of a suitable ultrasonic sensor isdisclosed in U.S. Pat. 5,148,700 (all of the contents of which areincorporated herein by reference). A suitable commercially availableacoustic sensor is sold by Entech Design, Inc., of Denton, Tex. underthe trademark MAPS™. Preferably, the sensor is operated at amultiplicity of frequencies and signal strengths. Suitable millimeterwave radar techniques used in conjunction with the present invention aredescribed in chapter 15 of Principles and Applications of MillimeterWave Radar, edited by N.C. Currie and C. E. Brown, Artecn House,Norwood, Mass. 1987. The ultrasonic technology referenced above can belogically extended to millimeter wave devices.

While the sensors may be utilized in a system such as shown in FIG. 12at a variety of locations, the arrows numbered 700, through 716 indicatethose positions where information relative to the chemical introductionwould be especially useful.

Referring now to FIG. 13, the surface treatment system of FIG. 12 isshown generally at 720. In accordance with the present invention, thechemical sensors (i.e. 700-716) will sense, in real time, parameters(i.e., concentration and classification) related to the introducedchemicals and supply that sensed information to a controller 722(preferably a computer or microprocessor based controller). Based onthat sensed information monitored by controller 722, the controller willinstruct a pump or other metering device 724 to maintain, vary orotherwise alter the amount of chemical and/or type of chemical beingadded to the surface treatment system 720 The supplied chemical fromtanks 726, 726′ and 726″ can, of course, comprise any suitable treatmentchemical such as those chemicals used to treat corrosion, break downemulsions, etc. Examples of suitable corrosion inhibitors include longchain amines or aminidiazolines. Suitable commercially availablechemicals include CronoxÔ which is a corrosion inhibitor sold by BakerPetrolite, a division of Baker-Hughes, Incorporated, of Houston, Tex.

Thus, in accordance with the control and monitoring system of FIG. 13,based on information provided by the chemical sensors 700-716,corrective measures can be taken for varying the injection of thechemical (corrosion inhibitor, emulsion breakers, etc.) into the system.The injection point of these chemicals could be anywhere upstream of thelocation being sensed such as the location where the corrosion is beingsensed. Of course, this injection point could include injectionsdownhole. In the context of a corrosion inhibitor, the inhibitors workby forming a protective film on the metal and thereby prevent water andcorrosive gases from corroding the metal surface. Other surfacetreatment chemicals include emulsion breakers which break the emulsionand facilitate water removal. In addition to removing or breakingemulsions, chemicals are also introduced to break out and/or removesolids, wax, etc. Typically, chemicals are introduced so as to providewhat is known as a base sediment and water (B. S. and W.) of less than1%.

In addition to the parameters relating to the chemical introductionbeing sensed by chemical sensors 700-716, the monitoring and controlsystem of the present invention can also utilize known corrosionmeasurement devices as well including flow rate, temperature andpressure sensors. These other sensors are schematically shown in FIG. 13at 728 and 730. The present invention thus provides a means formeasuring parameters related to the introduction of chemicals into thesystem in real time and on line. As mentioned, these parameters includechemical concentrations and may also include such chemical properties aspotential ionic content, the covalent content, pH level, oxygen levels,organic precipitates and like measurements. Similarly, oil/water cutviscosity and percent solids can be measured as well as paraffin andscale build-up, H₂S content and the like.

Another aspect of the invention is the ability to transmit opticalenergy downhole and convert it to another form of energy suitable foroperation of downhole devices. FIG. 14 shows a wellbore 802 with aproduction string 804 having one or more electrically-operated oroptically-operated devices, generally denoted herein by numeral 850 andone or more downhole sensors 814. The string 804 includes batteries 812which provide electrical power to the devices 850 and sensors 814. Thebatteries are charged by generating power downhole by turbines (notshown) or by supplying power for the surface via a cable (not shown).

In the present invention a light cell 810 is provided in the string 804which is coupled to an optical fiber 822 that has one or more sensors820 associated therewith. A light source 840 at the surface provideslight to the light cell 810 which generates electricity which chargesthe downhill batteries 812. The light cell 810 essentially tricklecharges the batteries. In many applications the downhole devices, suchas devices 850, are activated infrequently. Trickle charging thebatteries may be sufficient and thus may eliminate the use of otherpower generation devices. In applications requiring greater powerconsumption, the light cell may be used in conjunction with other powergenerator devices.

Alternatively, if the device 850 is optically-activated the fiber 822 iscoupled to the device 850 as shown by the dotted line 822 a and isactivated by supplying optical pulses from the surface unit 810. Thus inthe configuration of FIG. 14, a fiber optics device is utilized togenerate electrical energy downhole, which is then used to charge asource, such as a battery, or operate a device. The fiber 822 is alsoused to provide two-way communication between the DA/SP 842 and downholesensors and devices.

FIG. 15 is a schematic illustration of a wellbore system 900 utilizingthe fiber optic energy producing devices according one embodiment of thepresent invention. System 900 includes a wellbore 902 having a surfacecasing 901 installed a relatively short depth 904 a from the surface904. After the wellbore 902 has been drilled to a desired depth, acompletion or production string 906 is conveyed into the wellbore 902. Afiber optic energy generation device 920 placed in the string 906generates mechanical energy. The operation of the fiber optic device 920is described in reference to FIGS. 15A-15C.

The fiber optic device 920A shown in FIG. 15A contains a sealed chamber922 a containing a gas 923 which will expand rapidly when optical energysuch as laser energy is applied to the gas 923. A piston 924 a disposedin the device 920A moves outward when the gas 923 expands. When theoptical energy is not being applied to the gas 923; a spring 926 a oranother suitable device coupled to a piston rod 925 a forces the piston926 a back to its original position. The gas 923 is periodically chargedwith the optical energy conveyed to the device 920 a via an opticalconductor or fiber 944. FIG. 15B shows the optical device 920B wherein aspring 926 b is disposed within the enclosure 921 to urge the piston 924b back to its original position.

Referring back to FIG. 15, the outward motion of the member 925 of thedevice 920 causes a valve 930 to open allowing the wellbore fluid 908 atthe hydrostatic pressure to enter through port 932. The valve 930 iscoupled to hydraulically-operated device 935 in a manner that allows thefluid 908 under pressure to enter the device 935 via the port 932. Thus,in the configuration of FIG. 15, fiber optic device 920 controls theflow of the fluid 908 at the hydrostatic pressure to thehydraulically-operated device 935. The device 935 may be a packer, fluidvalve, safety valve, perforating device, anchor, sliding sleeve etc. Theoperation of the device 920 is preferably controlled from the surface904, a light source LS 940 provides the optical energy to the device 908via the fiber 944. One or more sensors 927 may be provided to obtainfeedback relating to the downhole operations. The sensors 927 providemeasurements relating to the fluid flow, force applied to the valve 930,downhole pressures, downhole temperatures etc. The signals from sensors927 may be processed downhole or sent to the surface data acquisitionand processing unit 942 via the fiber 944.

An alternate embodiment of a light actuated transducer for use in fluidflow control is shown in FIG. 15C. The device 950 includes aphotovoltaic cell 960 and a bi-morph element fluid valve cell 970.Optical energy from an optical fiber 944 is connected by means ofoptical lead 946 to a photovoltaic cell 960. The photovoltaic cell 960upon excitation by light produces an electric current that is conveyedby lead 962 to a bimetallic strip (bi-morph element) 964. Passage ofcurrent through the bimetallic strip causes it to bend to position 964′and move a ball 980 that rests in a valve seat 976. Motion of the ball980 away from the seat to 980′ enables a fluid 982 to flow through theinlet port 972 in the bi-morph element fluid valve cell 970 and theoutlet port 974. Other arrangements of the bimetallic strip and thevalve arrangement would be familiar to those versed in the art. Thisillustrates equipment in which optical energy is converted first toelectrical energy and then to mechanical motion.

In yet another embodiment of the invention (not shown), the opticalenergy is used to alter the physical properties of a photosensitivematerial, such as a gel, that is incorporated in a flow control device.Screens having a gravel pack are commonly used in oil and gas productionto screen out particulate matter. In one embodiment of the invention, aphotosensitive gel is used as the packing material in the screen.Activation of the gel by optical energy changes the physicalcharacteristics of the gel, partially crystallizing it. This makes itpossible to adjust the size of particles flowing through the screen.

FIG. 16 shows a wellbore system 1000 wherein the fiber optic devices1020 are used to operate one or more downhole devices and wherein thepressurized fluid is supplied through a conduit which also carries theoptical fiber to the devices 1020 from the surface 904. A valve 1030 isoperated by the fiber optic device 920 in the manner described abovewith reference to FIG. 15. Pressurized fluid 1032 from a source 1045 issupplied to the valve 1030 via a conduit 1010. The conduit 1010 theoptical fiber 1044 is pumped through the conduit from an the surface.Alternatively, the conduit 1010 containing the fiber 1044 may beassembled at the surface and deployed into the wellbore with the string1006. To operate the device 1035, the fiber optic device 920 is operatedand the fluid 1032 under pressure is continuously supplied to the valve1030 via the conduit 1010, which activates or sets the device 1035.Other downhole devices 1050 b, 1050 c etc. may be disposed in the string1006 or in the wellbore 1002. Each such device utilizes separate fiberoptic devices 920 and may utilize a common conduit 1010 for the opticalfiber 1044 and/or for the pressurized fluid 1032.

FIG. 17A shown a configuration utilizing multiple fiber optic devices1120 a-1120 c to generate rotary power. The devices 1120 a-1120 c aresimilar to the devices 920 described above. Light energy is preferablyprovided to such devices via a common optical fiber 1144. The source 940operates the devices 1120 a-1120 c in a particular order with apredetermined phase difference. An address system (not shown) may beutilized to address the devices by signals generated for such devices,The piston arms 1127 a-1127 c are coupled to a cam shaft 1125 atlocations 1125 a-1125 c respectively, which rotates in the direction1136 to provide rotary power. The rotary power may be utilized for anydenied purpose, such as to operate a pump or a generator to generateelectrical power.

FIGS. 17B-17C shows a configuration wherein the fiber optic devices areused to pump fluids. The fiber optic devices 1182 a of FIG. 17B containsa firing cylinder 1184 a and a second cylinder 1184 b. The second orhydraulic cylinder contains an outlet port 1183 b. Suitable fluid issupplied to the hydraulic cylinder via the inlet port 1183 a. When thedevice 1182 a is fired, the piston 1186 moves downward, blocking theinlet port 1183 a and simultaneously displacing the fluid 1186 from thecylinder 1184 b via the outlet port 1183 b. The spring 1185 forces thepiston 1186 to return to its original position, uncovering the inletport, until the next firing of the device 1182 a. In this manner thedevice 1182 a may be utilized to pump fluid. The flow rate is controlledby the firing frequency and the size of the fluid chamber 1184 b.

FIG. 17C shows two fiber optic devices 382 b and 382 c (similar to thedevice 382 a) connected in series to pump a fluid. In thisconfiguration, when the device 382 b is fired, fluid 390 from thechannels 391 of the device 382 discharges into the chamber 391 b of thedevice 382 c via line 392. A one-way check valve allows the fluid toflow only in the direction of the device 382 c. The firing of the device382 c discharges the fluid from the chamber 391 b via line 394 to thenext stage.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all variations within the scopeand spirit of the appended claims be embraced by the foregoingdisclosure.

What is claimed is:
 1. A light actuated system for use in a wellbore,comprising: (a) a light actuated transducer in the wellbore, said lightactuated transducer adapted to transform a physical state of a componentthereof upon application of optical energy; (b) an optical waveguideconveying the optical energy from a source thereof to the light actuatedtransducer; and (c) a control device in the wellbore operated at leastin part by said change in the physical state of the component of thelight actuated transducer to control an end use device in the wellbore.2. The light actuated system of claim 1, wherein said transformation ofthe physical state is selected from the set consisting of (i) mechanicalmotion of the component, and (ii) a change in the physical properties ofthe component.
 3. The light actuated system of claim 1 wherein theoptical waveguide is one of (i) an optical fiber, and (ii) afluid-filled waveguide.
 4. The light actuated system of claim 1 whereinthe transformation of the physical state includes the conversion of theoptical energy to motion of a piezoelectric materal.
 5. The lightactuated system of claim 1 further comprising a plurality of fiber opticsensors for making distributed measurements.
 6. The light actuatedsystem of claim 1 further comprising a processor adapted to providesignals responsive to downhole parameters for controlling a downholedevice.
 7. The light actuated system of claim 1 wherein transformationof the physical state generates rotary power.
 8. The light actuatedsystem of claim 1 wherein the control device is one of (i) a fluidcontrol device, (ii) an electronic power generation device, (iii) anelectrical switching device, (iv) a fluid pressuring device, (v) adownhole light source, and (vi) an energy sensitive material thatchanges physical properties.
 9. The light actuated system of claim 8 theend use device is selected from the group consisting of (i) flow controlequipment, (ii) lifting equipment, (iii) injection equipment, (iv)perforating equipment, (v) packer, (vi) fluid separating equipment,(vii) sensing equipment, (viii) pump, and (ix) fluid treatment.
 10. Thelight actuated system of claim 1 wherein transformation of the physicalstate includes the movement of a fluid and the source of the fluid isone of (i) a pressurized fluid supplied from a surface location, (ii)pressurized fluid supplied from the surface via a conduit carrying theoptical waveguide to the light actuated system, and (iii) wellbore fluidat hydrostatic pressure.
 11. The light actuated system of claim 10,further comprising a chamber containing the fluid, the chamber having areciprocating piston therein, said piston reciprocating due to theexpansion of the fluid upon application of optical energy.
 12. The lightactuated system of claim 1, wherein the transformation of the physicalstate comprises moving the component upon application of optical energy.13. The light actuated system of claim 12, wherein transducer comprisesa photovoltaic cell, said photovoltaic cell receiving the optical energyand converting it to electric current, said component receiving theelectric current and moving as a result thereof.
 14. The light actuatedsystem of claim 1 further comprising at least one sensor in the wellboreproviding measurements of at least one selected downhole parameter. 15.The light actuated system of claim 14 wherein the downhole parameter isone of (a) temperature, (b) pressure, (c) vibration, (d) acoustic filed,and (e) corrosion.
 16. The light actuated system of claim 14 wherein theat least one sensor comprises a plurality of spaced apart sensors. 17.The light actuated system of claim 1, wherein the transformation of thephysical state includes the expansion of a fluid.
 18. The method ofclaim 17, further comprising a chamber containing the fluid, the chamberhaving a reciprocating piston therein, said piston reciprocating due tothe expansion of the fluid upon application of optical energy.
 19. Thelight actuated system of claim 18, wherein said reciprocating piston isreciprocated to pump a fluid.
 20. The light actuated system of claim 19,further comprising a plurality of said reciprocating pistons and atleast two of said plurality of reciprocating pistons being in fluidcommunication with each other.
 21. The light actuated system of claim18, wherein the chamber further has a plurality of reciprocating pistonsthat are reciprocated to generate rotary power.
 22. The light actuatedsystem of claim 21, wherein optical energy is supplied to saidreciprocating pistons in a particular order with a predetermined phasedifference.
 23. The light actuated system of claim 21, wherein each ofsaid reciprocating pistons includes an arm and each of said arms iscoupled to a cam shaft that rotates to provide rotary power.
 24. Amethod for producing formation fluids through a wellbore, comprising:(a) providing a light actuated transducer in the wellbore, said lightactuated transducer adapted to transform a physical state of a componentthereof upon application of optical energy; (b) providing a controldevice in the wellbore that is operated at least in part by said changein the physical state of the component of the light actuated transducer;and (c) supplying optical energy to the light actuated transducer,causing said light actuated transducer to change the physical state ofthe component thereof, thereby operating the control device.
 25. Themethod of claim 24 wherein causing said light actuated transducer tochange the physical state of the component thereof further comprises aprocess selected from (i) moving the component, and, (ii) changing aphysical property of the component.
 26. The method of claim 24 furthercomprising providing a conduit supplying fluid under pressure to adevice in the wellbore.
 27. The method of claim 24 wherein the controldevice is one of (i) a fluid control device, (ii) an electronic powergeneration device, (iii) an electrical switching device, (iv) a fluidpressuring device, (v) a downhole light source, and (vi) an energysensitive material that changes physical properties.
 28. The method ofclaim 24 wherein causing said light actuated transducer to change thephysical state of the component thereof further comprises at least one:(i) controlling fluid flow using a fluid control device, (ii) generatingelectronic power, (iii) switching an electrical switching device, (iv)increasing pressure of a fluid using a pressuring device, (v) generatinglight using a downhole light source, and (vi) changing physicalproperties of an energy sensitive material.
 29. The method of claim 24further comprising using an end use device controlled at least in partby the control device, said end use device being one of (i) flow controlequipment, (ii) lifting equipment, (iii) injection equipment, (iv)perforating equipment, (v)packer, (vi) fluid separating equipment, (vii)sensing equipment, (viii) pump, and (ix) fluid treatment equipment. 30.The method of claim 24 wherein the transformation of the physical stateincludes the conversion of the optical energy to motion of apiezoelectric material carrying the electrical energy.
 31. The method ofclaim 24, further comprising converting the optical energy into anelectric current, passing the electric current through the component,and generating movement in the component as a result of the passingstep.
 32. The method of claim 24 wherein supplying optical energy to thelight actuated transducer further comprises using an optical waveguideselected from (i) an optical fiber, and (ii) a fluid-filled waveguide.33. The method of claim 32 further comprising providing a conduitcarrying the optical waveguide from the surface to the light actuatedtransducer.
 34. The method of claim 24 wherein transformation of thephysical state includes the movement of a fluid and the source of thefluid is one of (i) a pressurized fluid supplied from a surfacelocation, (ii) pressurized fluid supplied from the surface via a conduitcarrying the optical waveguide to the light actuated system, and (iii)wellbore fluid at hydrostatic pressure.
 35. The method of claim 34further comprising using an end use device controlled at least in partby the control device, said end use device being one of (i) flow controlequipment, (ii) lifting equipment, (iii) injection equipment, (iv)perforating equipment, (v) packer, (vi) fluid separating equipment,(vii) sensing equipment, (viii) pump, and (ix) fluid treatmentequipment.
 36. The method of claim 24 further comprising using at leastone sensor in the wellbore for providing measurements of at least oneselected downhole parameter.
 37. The method of claim 36 wherein thedownhole parameter is one of (a) temperature, (b) pressure, (c)vibration, (d) acoustic field, and (e) corrosion.
 38. The method ofclaim 36 further comprising a using a plurality of fiber optic sensorsfor making distributed measurements of a selected downhole parameter.39. The method of claim 24, wherein transforming the physical statecomprises expanding a fluid upon application of optical energy.
 40. Themethod of claim 39, further comprising reciprocating a piston due to theexpansion of the fluid upon application of optical energy.
 41. Themethod of claim 40, further comprising pumping a fluid as a result ofthe reciprocating step.
 42. The method of claim 40, further comprisingreciprocating a plurality of said pistons to generate rotary power. 43.The method of claim 42, further comprising supplying optical energy tosaid reciprocating pistons in a particular order with a predeterminedphase difference.
 44. The method of claim 43, further comprisinggenerating rotary power as a result of the supplying step.